- Hereford Field ("Hereford") drilling and completion operations commenced within a month of closing transaction

- Reported production sales volumes of 1.91 million barrels of oil equivalent ("MMBoe") for the first quarter of 2018 were at the mid-point of guidance

- DJ Basin production sales volumes of 2.2 MMBoe for the first quarter of 2018, pro forma to include full quarter Hereford volumes, represent an increase of 74% from the first quarter of 2017

- DJ Basin oil price differential of $2.42 per barrel, improved 13% from the first quarter of 2017

- Drilling and completion cycle times improve 7% compared to 2017 and set a new Company record by averaging 4.2 frac days per well with over 400 frac stages completed on a recent five-well drilling and spacing unit ("DSU")

- Reiterate 2018 financial and operating guidance and 2019 outlook; second quarter of 2018 production sales volumes expected to approximate 2.4-2.5 MMBoe, a sequential increase of approximately 11% at the mid-point from the first quarter, pro forma for Hereford volumes

Chief Executive Officer and President Scot Woodall commented, "It is an exciting time for HighPoint Resources as we achieved a significant milestone with the closing of the Fifth Creek business combination in March. Together, we began a new era as a premier oil-weighted and rural DJ Basin focused company. Going forward, we are positioned to deliver a step change improvement to production growth, cash flow and EBITDAX with an associated enhancement to credit metrics. We have quickly and smoothly integrated the Hereford asset and have hit the ground running with respect to the 2018 development program. The Hereford development and completion program is proceeding as anticipated and we look forward to providing a further update over the coming quarters.

"We are off to a fast start with our legacy NE Wattenberg program, delivering another solid quarter with respect to our guidance and highlighted by strong operational execution. The team has done an excellent job of maintaining well costs at levels consistent with internal expectations and managing through minor constraints associated with third party natural gas processing facilities allowing us to meet our first quarter objectives. We are on track to achieve our objectives with three drilling rigs and two completion crews currently operating and are reiterating our 2018 and 2019 guidance.

"We are well positioned for long-term shareholder value creation with a dominant acreage position in the oil-weighted and rural core of the DJ Basin. With a focus on returns and disciplined capital allocation, our inventory of more than 2,800 undeveloped drilling locations (95% XRL) can generate robust wellhead economics and top-tier margins in a $50 plus per barrel WTI pricing environment. We have a strong technical team that is executing at a very high level and have high confidence in achieving our objectives as the close proximity of Hereford to our legacy acreage allows us to immediately transfer and apply our proven execution skill set and cost structure across our total acreage position. Finally, we are in a good financial position with current liquidity consisting of cash on hand of $225 million and an undrawn $300 million credit facility."

For the first quarter of 2018, the Company reported a net loss of $24.9 million, or $0.20 per diluted share. Adjusted net income for the first quarter of 2018 was a net loss of $5.9 million, or $0.05 per diluted share. EBITDAX for the first quarter of 2018 was $46.7 million. Adjusted net income (loss) and EBITDAX are non-GAAP (Generally Accepted Accounting Principles) measures. Please reference the reconciliations to GAAP financial statements at the end of this release.

OPERATING AND FINANCIAL RESULTS

The following table summarizes certain operating and financial results for the first quarter of 2018 and 2017:

Three Months EndedMarch 31,

2018

2017

Change

Combined production sales volumes (MBoe)

1,914

1,433

34

%

Net cash provided by (used in) operating activities ($ millions)

$

54.3

$

38.1

43

%

Discretionary cash flow ($ millions) (1)

$

34.9

$

22.9

52

%

Combined realized prices with hedging (per Boe)

$

37.86

$

37.71

—

%

Net income (loss) ($ millions)

$

(24.9)

$

(13.1)

(90)

%

Per share, basic

$

(0.20)

$

(0.18)

(11)

%

Per share, diluted

$

(0.20)

$

(0.18)

(11)

%

Adjusted net income (loss) ($ millions) (1)

$

(5.9)

$

(11.6)

49

%

Per share, basic

$

(0.05)

$

(0.16)

69

%

Per share, diluted

$

(0.05)

$

(0.16)

69

%

Weighted average shares outstanding, basic (in thousands)

123,596

74,544

66

%

Weighted average shares outstanding, diluted (in thousands)

123,596

74,544

66

%

EBITDAX ($ millions) (1)

$

46.7

$

36.1

29

%

(1)

Discretionary cash flow, adjusted net income (loss) and EBITDAX are non-GAAP (Generally Accepted Accounting Principles) measures. Please reference the reconciliations to GAAP financial statements at the end of this release.

The Company reported oil, natural gas and natural gas liquids ("NGL") production of 1.91 MMBoe in the first quarter of 2018, which was at the mid-point of the guidance range of 1.8-2.0 MMBoe. Pro forma production sales volumes for the DJ Basin were approximately 2.2 MMBoe, which was an increase of 74% over the first quarter of 2017, and consisted of production from the legacy NE Wattenberg of approximately 1.9 MMBoe and Hereford volumes of approximately 0.3 MMBoe for the first quarter of 2018. Production sales volumes were comprised of approximately 60% oil, 22% natural gas and 18% NGLs.

For the first quarter of 2018, WTI oil prices averaged $62.87 per barrel, NWPL natural gas prices averaged $2.49 per MMBtu and NYMEX natural gas prices averaged $3.03 per MMBtu. Commodity price realizations to benchmark pricing were oil less $2.42 per barrel versus WTI and natural gas less $0.54 per Mcf compared to NWPL. The NGL price averaged approximately 32% of the WTI price per barrel.

For the first quarter of 2018, the Company had derivative commodity swaps in place for 9,829 barrels of oil per day tied to WTI pricing at $52.89 per barrel, 5,000 MMBtu of natural gas per day tied to NWPL regional pricing at $2.68 per MMBtu and no hedges in place for NGLs.

Three Months EndedMarch 31,

2018

2017

Change

Average Realized Prices before Hedging:

Oil (per Bbl)

$

60.45

$

47.92

26

%

Natural gas (per Mcf)

1.95

2.66

(27)

%

NGLs (per Bbl)

20.31

20.04

1

%

Combined (per Boe)

42.24

35.18

20

%

Average Realized Prices with Hedging:

Oil (per Bbl)

$

53.00

$

52.41

1

%

Natural gas (per Mcf)

1.98

2.62

(24)

%

NGLs (per Bbl)

20.31

20.04

1

%

Combined (per Boe)

37.86

37.71

—

%

LOE averaged $3.27 per Boe in the first quarter of 2018 compared to $4.09 per Boe in the first quarter of 2017. The year-over-year reduction in LOE is a result of improved operating efficiencies, disposition of higher LOE wells and lease operating cost reductions. First quarter LOE is typically higher compared to the remainder of the year due to increased seasonal operating costs, including annual compressor maintenance.

Production tax expense averaged $2.70 per Boe in the first quarter of 2018 compared to $0.22 per Boe in the first quarter of 2017. Higher production tax expense in the first quarter of 2018 was related to an adjustment of Colorado ad valorem tax based on actual assessments and of the related Colorado severance tax credit adjustment which was recorded in the first quarter of 2017.

Depreciation, depletion and amortization ("DD&A") averaged $21.41 per Boe in the first quarter of 2018 compared to $26.76 per Boe in the first quarter of 2017. Lower DD&A on a per unit basis compared to the first quarter of 2017 was primarily the result of proved reserves added at lower costs.

Three Months EndedMarch 31,

2018

2017

Change

Average Costs (per Boe):

Lease operating expenses

$

3.27

$

4.09

(20)

%

Gathering, transportation and processing expense

0.22

0.34

(35)

%

Production tax expenses

2.70

0.22

*nm

Depreciation, depletion and amortization

21.41

26.76

(20)

%

General and administrative expense

5.28

6.52

(19)

%

*

Not meaningful

Debt and Liquidity

At March 31, 2018, the principal debt balance was $627.2 million, while cash and cash equivalents were $224.7 million, resulting in net debt of $402.5 million. Cash and cash equivalents were used during the quarter to execute on the first quarter development program and to repay $54 million of Fifth Creek Energy outstanding debt in conjunction with closing the business combination.

The Company currently has $274 million in available borrowing capacity on its $300 million credit facility, after taking into account a $26 million letter of credit.

Capital Expenditures

Capital expenditures for the first quarter of 2018 totaled $112.1 million. The Company operated two drilling rigs during the quarter and capital projects included spudding 20 extended reach lateral ("XRL") wells in NE Wattenberg and placing 22 XRL wells on initial flowback. There were minimal capital expenditures associated with Hereford as drilling and completion operations were initiated in April. Higher capital expenditures relative to guidance was due to the Company opportunistically adding higher working interests in NE Wattenberg wells drilled during the first quarter, the timing of completion activity and accelerating infrastructure investment to coincide with planned development and to provide mid-stream flexibility.

Capital expenditures included $98.1 million for drilling and completion operations, $0.5 million for leaseholds, and $13.5 million for infrastructure and corporate assets.

OPERATIONAL UPDATE

The Company is currently operating three drilling rigs in the DJ Basin with two rigs in NE Wattenberg and one rig in Hereford. The Company expects the three-rig program will drill approximately 120-125 gross XRL wells in 2018. Two completion crews will be utilized in 2018 and the Company has the ability to add a third completion crew, as necessary, based on the timing of well completions. The drilling program is designed to provide flexibility to opportunistically adjust activity between NE Wattenberg and Hereford to maximize development and completion efficiencies. It is anticipated that the drilling program will be adjusted in the third quarter to include two rigs in Hereford and one rig in NE Wattenberg.

NE Wattenberg

The Company produced an average of 20,845 Boe/d (59% oil) in the first quarter of 2018 in NE Wattenberg, representing 47% growth over the first quarter of 2017. The NE Wattenberg oil price differential averaged $2.42 per barrel less than WTI. For the first quarter of 2018, the Company drilled 20 XRL wells and placed 22 XRL wells on initial flowback.

The Company reported positive results from its NE Wattenberg optimized completions targeting the Niobrara B and Niobrara C formations that included increased sand concentrations, tighter frac stage spacing, and enhanced flowback methods. The average twelve month cumulative oil production of wells in the 2017 program was 47% greater than the average for wells completed in 2015 and recent wells on average continue to meet or exceed the NE Wattenberg base XRL type-curve.

Recent completion activity was highlighted by DSU 5-61-20, which is located in the central area of NE Wattenberg and is the eastern-most DSU completed to date. Initial flowback began in the fourth quarter of 2017 and early production data is encouraging as the wells continue to perform consistent with the base type-curve through the initial 90 days of production, validating the consistency and attractiveness of the asset base. DSUs 4-62-29, 4-62-32 and 3-62-4 were placed on initial flowback during the first quarter and are trending towards peak production.

The Company continues to achieve drilling and completion efficiencies in the current operating environment as recent XRL well drilling days to rig release averaged under 7 days per well, representing a further improvement over the 2017 average. Drilling and completion cycle times improved by 7% to approximately 16 days, driven by a 14% improvement in completion times (frac and drill out days). The Company set a record during the quarter by averaging 4.2 days per well to frac a recent five-well DSU that included over 400 frac stages being completed.

Hereford Field

Pro forma production sales volumes for the first quarter of 2018 averaged approximately 3,820 Boe/d (76% oil) and the oil price differential averaged $2.08 per barrel less than WTI. There was no new drilling and completion activity during the first quarter. Drilling operations were initiated in April on DSU 11-63-14, which includes ten XRL wells. It is anticipated that the wells will be placed on initial flowback during the third quarter of 2018. In addition, a full-time completion crew began operating in April and completion operations commenced on previously drilled, but not completed, XRL wells. The wells will incorporate optimized completions, including controlled flowback methods, and are anticipated to be placed on initial flowback during the second quarter of 2018. The focus of the 2018 development program will be on full DSU development to maximize drilling and completion efficiencies.

2018 OPERATING GUIDANCE

The Company is reiterating its 2018 and 2019 operating guidance outlook and providing second quarter of 2018 guidance for capital expenditures and production as discussed below. See "Forward-Looking Statements" below.

Capital expenditures of $500-$550 million, unchanged

Second quarter capital expenditures are expected to total $135-$145 million

Pro forma production of 11.0-11.5 MMBoe, unchanged

Second quarter production sales volumes are expected to approximate 2.4-2.5 MMBoe, which represents an approximate 11% sequential increase from the first quarter of 2018

Second quarter production is expected to be weighted approximately 60% oil

The following table summarizes our current hedge position as of May 8, 2018:

Oil (WTI)

Natural Gas (NWPL)

Period

VolumeBbls/d

Price$/Bbl

VolumeMMBtu/d

Price$/MMBtu

2Q18

11,637

52.98

5,000

2.68

3Q18

13,843

54.62

5,000

2.68

4Q18

13,806

54.63

5,000

2.68

1Q19

13,524

56.66

—

—

2Q19

13,500

56.67

—

—

3Q19

12,481

56.70

—

—

4Q19

12,462

56.71

—

—

Realized sales prices will reflect basis differentials from the index prices to the sales location.

UPCOMING EVENTS

First Quarter Conference Call and Webcast

The Company plans to host a conference call on Wednesday, May 9, 2018, to discuss first quarter of 2018 results. The call is scheduled at 10:00 a.m. Eastern time (8:00 a.m. Mountain time). Please join the webcast conference call live or for replay via the Internet at www.hpres.com, accessible from the home page. To join by telephone, call (855) 760-8152 ((631) 485-4979 international callers) with passcode 3669649. The webcast will remain on the Company's website for approximately 7 days and a replay of the call will be available through May 16, 2018 at (855) 859-2056 ((404) 537-3406 international) with passcode 3669649.

Investor Events

Members of the Company's management are currently scheduled to participate in the following investor events:

All statements in this press release, other than statements of historical fact, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Words such as expects, forecast, guidance, anticipates, intends, plans, believes, seeks, estimates and similar expressions or variations of such words are intended to identify forward-looking statements herein; however, these are not the exclusive means of identifying forward-looking statements. In particular, the Company is providing "2018 Operating Guidance," which contains projections for certain 2018 operational and financial metrics. Additional forward-looking statements in this release relate to, among other things, future capital expenditures, costs, projects and opportunities; and the availability of adequate natural gas processing capacity.

These and other forward-looking statements in this press release are based on management's judgment as of the date of this release and are subject to numerous risks and uncertainties. Actual results may vary significantly from those indicated in the forward-looking statements. Please refer to the Bill Barrett Corporation's Annual Report on Form 10-K for the year ended December 31, 2017 filed with the SEC, and other filings, including our Current Reports on Form 8-K and Quarterly Reports on Form 10-Q, all of which are incorporated by reference herein, for further discussion of risk factors that may affect the forward-looking statements. The Company encourages you to consider the risks and uncertainties associated with projections and other forward-looking statements and to not place undue reliance on any such statements. In addition, the Company assumes no obligation to publicly revise or update any forward-looking statements based on future events or circumstances.

ABOUT HIGHPOINT RESOURCES CORPORATION

HighPoint Resources Corporation (NYSE: HPR) is a Denver, Colorado based company focused on the development of oil and natural gas assets located in the Denver-Julesburg Basin of Colorado. Additional information about the Company may be found on its website at www.hpres.com.

HIGHPOINT RESOURCES CORPORATION

Selected Operating Highlights

(Unaudited)

Three Months EndedMarch 31,

2018

2017

Production Data:

Oil (MBbls)

1,137

825

Natural gas (MMcf)

2,562

1,890

NGLs (MBbls)

350

293

Combined volumes (MBoe)

1,914

1,433

Daily combined volumes (Boe/d)

21,267

15,922

Average Sales Prices (before the effects of realized hedges):

Oil (per Bbl)

$

60.45

$

47.92

Natural gas (per Mcf)

1.95

2.66

NGLs (per Bbl)

20.31

20.04

Combined (per Boe)

42.24

35.18

Average Realized Sales Prices (after the effects of realized hedges):

Oil (per Bbl)

$

53.00

$

52.41

Natural gas (per Mcf)

1.98

2.62

NGLs (per Bbl)

20.31

20.04

Combined (per Boe)

37.86

37.71

Average Costs (per Boe):

Lease operating expenses

$

3.27

$

4.09

Gathering, transportation and processing expense

0.22

0.34

Production tax expenses

2.70

0.22

Depreciation, depletion and amortization

21.41

26.76

General and administrative expense (1)

5.28

6.52

(1)

Includes long-term cash and equity incentive compensation of $0.75 per Boe and $0.79 per Boe for the three months ended March 31, 2018 and 2017, respectively.

HIGHPOINT RESOURCES CORPORATION

Consolidated Condensed Balance Sheets

(Unaudited)

As ofMarch 31,

As ofDecember 31,

2018

2017

(in thousands)

Assets:

Cash and cash equivalents

$

224,692

$

314,466

Other current assets

52,661

53,197

Property and equipment, net

1,811,442

1,018,880

Other noncurrent assets

3,679

4,163

Total assets

$

2,092,474

$

1,390,706

Liabilities and Stockholders' Equity:

Current liabilities (1)

240,388

148,934

Long-term debt, net of debt issuance costs

616,244

617,744

Other long-term liabilities (1)

175,502

25,474

Stockholders' equity

1,060,340

598,554

Total liabilities and stockholders' equity

$

2,092,474

$

1,390,706

(1)

At March 31, 2018, the estimated fair value of all of the Company's commodity derivative instruments was a liability of $44.4 million, comprised of $35.9 million of current liabilities and $8.5 million of non-current liabilities. This amount will fluctuate based on estimated future commodity prices and the current hedge position.

HIGHPOINT RESOURCES CORPORATION

Consolidated Statements of Operations

(Unaudited)

Three Months EndedMarch 31,

2018

2017

(in thousands, except per shareamounts)

Operating Revenues:

Oil, gas and NGL production

$

80,831

$

50,425

Other operating revenues, net

(21)

111

Total operating revenues

80,810

50,536

Operating Expenses:

Lease operating

6,251

5,862

Gathering, transportation and processing

419

489

Production tax

5,175

322

Exploration

13

27

Impairment, dry hole costs and abandonment

317

8,074

(Gain) Loss on sale of properties

408

(92)

Depreciation, depletion and amortization

40,985

38,340

Unused commitments

4,538

4,572

General and administrative (1)

10,107

9,349

Merger transaction expense

4,763

—

Other operating expenses, net

39

(573)

Total operating expenses

73,015

66,370

Operating Income (Loss)

7,795

(15,834)

Other Income and Expense:

Interest and other income

691

206

Interest expense

(13,090)

(13,951)

Commodity derivative gain (loss) (2)

(20,333)

16,464

Total other income and expense

(32,732)

2,719

Income (Loss) before Income Taxes

(24,937)

(13,115)

(Provision for) Benefit from Income Taxes

—

—

Net Income (Loss)

$

(24,937)

$

(13,115)

Net Income (Loss) per Common Share

Basic

$

(0.20)

$

(0.18)

Diluted

$

(0.20)

$

(0.18)

Weighted Average Common Shares Outstanding

Basic

123,596

74,544

Diluted

123,596

74,544

(1)

Includes long-term cash and equity incentive compensation of $1.4 million and $1.1 million for the three months ended March 31, 2018 and 2017, respectively.

(2)

The table below summarizes the realized and unrealized gains and losses the Company recognized related to its oil and natural gas derivative instruments for the periods indicated:

Realized and unrealized gains and losses on commodity derivatives are presented herein as separate line items but are combined for a total commodity derivative gain (loss) in the Consolidated Statements of Operations. This separate presentation is a non-GAAP measure. Management believes the separate presentation of the realized and unrealized commodity derivative gains and losses is useful because the realized cash settlement portion provides a better understanding of the Company's hedge position. The Company also believes that this disclosure allows for a more accurate comparison to its peers.

Adjusted (provision for) benefit from income taxes is calculated using the Company's current effective tax rate prior to applying the valuation allowance against deferred tax assets.

EBITDAX Reconciliation

Three Months EndedMarch 31,

2018

2017

(in thousands)

Net Income (Loss)

$

(24,937)

$

(13,115)

Adjustments to reconcile to EBITDAX:

Depreciation, depletion and amortization

40,985

38,340

Impairment, dry hole and abandonment expense

317

8,074

Exploration expense

13

27

Unrealized derivative (gain) loss

11,945

(12,832)

Incentive compensation and other non-cash charges

835

1,968

Merger transaction expense

4,763

—

(Gain) loss on sale of properties

408

(92)

Interest and other income

(691)

(206)

Interest expense

13,090

13,951

Provision for (benefit from) income taxes

—

—

EBITDAX

$

46,728

$

36,115

Discretionary cash flow, adjusted net income (loss) and EBITDAX are non-GAAP measures. These measures are presented because management believes that they provide useful additional information to investors for analysis of the Company's performance. If used as a liquidity measure, they should be reconciled to cash flow from operations as well as adjusting net income (loss) for certain items to allow for a more consistent comparison from period to period. In addition, the Company believes that these measures are widely used by professional research analysts and others in the valuation, comparison and investment recommendations of companies in the oil and gas exploration and production industry, and that many investors use the published research of industry research analysts in making investment decisions.

These measures should not be considered in isolation or as a substitute for net income, income from operations, net cash provided by operating activities or other income, profitability, cash flow or liquidity measures prepared in accordance with GAAP. The definition of these measures may vary among companies, and, therefore, the amounts presented may not be comparable to similarly titled measures of other companies.